Hydrocarbons are produced from an underground reservoir formation in which they are trapped through a wellbore that is drilled into the formation. The term “oil” is used generically to include gas and condensate. The reservoir formations are typically either sandstones or carbonates. Formations that are considered to be carbonate may contain some sandstone and vice versa. Oil will flow through the formation rock if it has pores of sufficient size and number to allow a flowpath for the oil to move through the formation. In order for oil to be produced, that is, travel from the formation to the wellbore (and ultimately to the surface) there must also be a sufficiently unimpeded flowpath from the formation to the wellbore.
One of the most common reasons for a decline in oil production is damage to the formation, which at least partially plugs the rock pores and therefore impedes the flow of oil. Sources of formation damage include: particles that have coated the wellbore face or invaded the near-wellbore matrix from the drilling and/or completion fluid; particles that were part of the formation that have been mobilized by drilling, completion or production; and paraffins, asphaltenes, or minerals that have precipitated due to mixing of incompatible fluids or to temperature or pressure changes (precipitated minerals are commonly called scale). This damage generally arises from another fluid deliberately injected into the wellbore, for instance, drilling or completion fluid. The natural effect of all of this damage is to decrease permeability to oil moving from the formation in the direction of the wellbore.
Another reason for lower-than-expected production may be that the formation is naturally “tight” (low permeability); that is, the pores are sufficiently small that the oil migrates toward the wellbore only very slowly. The common denominator in both cases (damage and naturally tight reservoirs) is low permeability. Techniques performed by hydrocarbon producers to increase the net permeability of the reservoir are referred to as “stimulation techniques.” Essentially, one can perform a stimulation technique by: (1) injecting chemicals through the wellbore and into the formation to react with and dissolve the wellbore and/or near-wellbore damage (2) injecting chemicals through the wellbore and into the formation to react with and dissolve small portions of the formation to create alternative flowpaths for the hydrocarbon (thus rather than removing the damage, redirecting the migrating oil around the damage); or (3) injecting chemicals through the wellbore and into the formation at pressures sufficient to actually fracture the formation, thereby creating a large flow channel through which hydrocarbon can more readily move from the formation and into the wellbore. Processes (1) and (2) are called “matrix stimulation,” commonly “matrix acidizing” since the chemicals are usually acids or acid-based fluids (although they may be other formation-dissolving materials such as certain chelating agents such as aminopolycarboxylic acids), and process (3) can be either “acid fracturing” or “hydraulic fracturing”. Process (1) is typically applied in sandstone reservoirs because sandstones are usually as difficult or more difficult to dissolve than are the contributors to the damage. Process (2) is typically applied in carbonates because carbonates are usually easier to dissolve than some or all of the damaging materials. Process (3) is applied to both lithologies.
Embodiments of the Present Invention are directed primarily to the first of these three processes. At present, matrix acidizing treatments, including the sandstone matrix acidizing treatments that are the subject of the remainder of this discussion, are plagued primarily by four very serious limitations: (1) inadequate radial penetration; (2) incomplete axial distribution; (3) corrosion of the pumping and well bore tubing (which will not be considered further here); and (4) damage to the formation caused by the acid itself. Embodiments of the Present Invention are directed primarily to the second and fourth problems.
The first problem, inadequate radial penetration, is caused by the fact that when the acid is introduced into the formation it reacts with the damaging material and/or formation matrix, with which it first comes into contact. (This is usually at or near the wellbore, and we will discuss the problem as though that were the case, although in some instances—for example where there are natural fractures—the location at which the majority of first contact of the treatment fluid with the formation occurs may be distant from the wellbore.) The formation near the wellbore that first contacts the acid is adequately treated, though portions of the formation more distal to the wellbore (as one moves radially, outward from the wellbore) remain untouched by the acid—since all of the acid reacts before it can get there. For instance, sandstone formations are often treated with a mixture of hydrofluoric and hydrochloric acids at sufficiently low injections rates as to avoid fracturing the formation. This acid mixture is often selected because it will dissolve clays (found in drilling mud) as well as the primary constituents of naturally occurring sandstones (e.g., silica, feldspar, and calcareous material). In fact, the dissolution may be so effective that the injected acid is essentially spent by the time it reaches a few inches beyond the wellbore. Thus, one can calculate that over 100 gallons of acid per foot is required to fill a region five feet from the wellbore (assuming 20% porosity and 6-inch wellbore diameter). In fact, due to such limited penetration, it is believed that sandstone matrix treatments do not provide significant stimulation beyond what is achieved through near-wellbore damage removal. Yet damage at any point along the hydrocarbon flowpath can impede flow (hence production). Therefore, because of the prodigious fluid volumes required, these treatments are severely limited by their cost.
A second major problem that severely limits the effectiveness of matrix acidizing technology is incomplete axial distribution. This problem relates to the proper placement of the acid-containing fluid—i.e., ensuring that it is delivered to the desired zone (i.e., the zone that needs stimulation) rather than another zone. (Hence this problem is not related per se to the effectiveness of the acid-containing fluid.) More particularly, when an oil-containing formation is injected with acid, the acid begins to dissolve the damage and/or the matrix. Depending upon the reactivity of the acid with the matrix and the flow rate of acid to the reaction location, as one continues to pump the acid into the formation, a dominant channel through the matrix is very often created. As one continues to pump acid into the formation, the acid will naturally flow along that newly created channel—i.e., the path of least resistance—and therefore leave the rest of the formation substantially untreated. In matrix stimulation, the formation of such channels, commonly called wormholes, is usually undesirable. This behavior is exacerbated by intrinsic permeability heterogeneity (common in many formations) especially natural fractures in the formation and high permeability streaks. Again, these regions of heterogeneity in essence attract large amounts of the injected acid, hence keeping the acid from reaching other parts of the formation along the wellbore—where it is actually desired most. Thus, in many cases, a substantial fraction of the productive, oil-bearing intervals within the zone to be treated are not contacted by acid sufficient to penetrate deep enough (laterally in the case of a vertical wellbore) into the formation matrix to effectively increase its permeability and therefore its capacity for delivering oil to the wellbore. This problem of proper placement is a particularly vexing one since the injected fluid will preferentially migrate to higher permeability zones (the path of least resistance) rather than to the lower permeability zones—yet it is those latter zones which require the acid treatment (i.e., because they are low permeability zones, the flow of oil through them is diminished). In response to this problem, numerous, disparate techniques have evolved to achieve more controlled placement of the fluid—i.e., to divert the acid away from naturally high permeability zones and zones already treated, and towards the regions of interest.
The techniques to control acid placement (i.e., to ensure effective zone coverage) can be roughly divided into either mechanical or chemical techniques. Mechanical techniques include ball sealers (balls dropped into the wellbore and that plug the perforations in the well casing, thus sealing the perforation against fluid entry); packers and bridge plugs, particularly including straddle packers (mechanical devices that plug a portion of the wellbore and thereby inhibit fluid entry into the perforations around that portion of the wellbore); coiled tubing (flexible tubing deployed by a mechanized reel, through which the acid can be delivered with more precise locations within the wellbore); and bullheading (attempting to achieve diversion by pumping the acid at the highest possible pressure—just below the pressure that would actually fracture the formation). Chemical techniques can be further divided into ones that chemically modify the wellbore adjacent to portions of the formation for which acid diversion is desired, and ones that modify the acid-containing fluid itself. The first type involve materials that form a reduced-permeability cake on the wellbore face which upon contact with the acid, will divert it to higher permeability regions particulate material. These are typically either oil-soluble or water-soluble particulates that are directed at the high permeability zones to plug them and therefore divert acid flow to the low permeability zones. The second type includes foaming agents, emulsifying agents, and gelling agents. Mechanical methods and chemical methods that chemically modify the wellbore adjacent to portions of the formation for which acid diversion is desired will not be considered further here.
Emulsified acid systems and foamed systems are commercially available responses to the diversion problem, but they are fraught with operational complexity which severely limits their use—e.g., flow rates of two fluids, and bottom hole pressure must be meticulously monitored during treatment. That leaves gelling agents—the class of diverters to which Embodiments of the Present Invention belong. Though they are commercially available, gelling agents are quite often undesirable in matrix acidizing since the increased viscosity makes the fluid more difficult to pump (i.e., the same resistance to flow that confers the pressure build-up in the formation and results in the desired diversion, actually makes these fluids difficult to pump). Some commercially available systems are polymeric cross-linked systems—i.e., they are linear polymers when pumped but a chemical agent pumped along with the polymer causes the polymers to aggregate or cross-link once in the wellbore, which results in gelling. Unfortunately, these systems leave a residue in the formation, which can damage the formation, resulting in diminished hydrocarbon production. Severe well plugging, particularly in low pressure wells, caused by these systems has been well documented. In addition, the success of these systems is naturally dependent upon a very sensitive chemical reaction—the cross-linking—which is very difficult to optimize so that it is delayed during pumping but maximized once the chemicals are in the wellbore. This reaction is easily perturbed by formation chemistry, contaminants in the pumping equipment, and so forth. And again, once these systems are in place, they are difficult to remove—to do so requires that they be somehow un-cross linked and/or that the polymer be destroyed.
Viscoelastic surfactant-based gelling systems can avoid these problems. One viscoelastic surfactant-based gelling system is disclosed in U.S. Pat. Nos. 5,979,557 and 6,435,277, which have a common assignee as the present application. This system differs from Embodiments of the Present Invention in that it is not a self-diverting system—i.e., the treatment is performed in two steps: (1) injecting the diverter, followed by (2) injecting the acid. The treatments based on the fluids of Embodiments of the Present Invention are based on a single step—hence it is chemically very different—because the diverter is contained within the acid-containing fluid.
Another viscoelastic surfactant-based gelling system is disclosed in U.S. Pat. No. 6,399,546, and U.S. patent application Ser. No. 10/065,144, which also have a common assignee as the present application. This system, which we will call “VDA” here (for “viscoelastic diverting acid”) was developed for carbonate matrix acidizing and may contain one of certain zwitterionic surfactants, such as those based on betaines (which are described in U.S. Pat. No. 6,258,859, and which we will call BET surfactants), an acid that is hydrochloric, hydrofluoric, a mixture of hydrochloric and hydrofluoric, acetic or formic acid, and (for some BET surfactants) a required co-surfactant or (for other BET surfactants) optional methanol, ethanol or isopropanol. The acid is not a mixture of inorganic and organic acids. The initially injected fluid has a nearly water-like viscosity, but after a considerable portion of the acid “spends,” or has been consumed, (which is possible because it is being injected into a carbonate formation that will react with a large amount of acid) the viscosity increases substantially. Thus, when first injected, VDA's enter the most permeable zone(s), but when they gel they block that zone or zones and divert subsequently injected fluid into previously less-permeable zones. The success of such systems depends upon the ability of the formation to react with a large amount of acid. Consequently, they are most useful with carbonates that have a large capacity to react with acid.
SPE paper 80274, “Application of Novel Diversion Acidizing Techniques To Improve Gas Production in Heterogeneous Formation,” describes a “diversion acid” that is a strong gel when injected. There is no indication of the chemistry; a breaker is required.
A need exists for a diversion system that will be effective in sandstones—i.e., a fluid that is not damaged by shear, has a low viscosity during pumping, that gels quickly once it contacts sandstone, that forms a gel of sufficient strength to allow diversion to occur, and that is immediately and nearly completely “broken” or returned to the un-gelled state, without the need for a breaker, after the treatment has ceased so the well can be put back on production. Furthermore, this fluid must not only be self-diverting, but it must also divert subsequently-injected fluids until a treatment is completed.